PROJECT DESIGN DOCUMENT (PDD)

Transcription

1 CDM Executive Board Page 1 PROJECT DESIGN DOCUMENT FORM FOR CDM PROJECT ACTIVITIES (F-CDM-PDD) Version 04.1 PROJECT DESIGN DOCUMENT (PDD) Title of the project activity Project Lumut Balai Unit 3 4 PT. Pertamina Geothermal Energy Version number of the PDD 03.1 Completion date of the PDD 06/08/2012 Project participant(s) South Pole Carbon Asset Management Ltd. PT. Pertamina Geothermal Energy Host Party(ies) Republic of Indonesia Sectoral scope and selected methodology(ies) Sectoral scope: (1) Energy industries (renewable - / non-renewable sources) Selected methodology: ACM0002 Consolidated baseline methodology for grid connected electricity generation from renewable sources version Estimated amount of annual average GHG 581,784 t.co 2 e emission reductions

2 CDM Executive Board Page 2 SECTION A. Description of project activity A.1. Purpose and general description of project activity >> The Project Lumut Balai Unit 3 4 PT. Pertamina Geothermal Energy (hereafter referred to as Lumut Balai II 1 or the Project) developed by PT. Pertamina Geothermal Energy (PGE), hereafter referred to as the Project Developer, is a geothermal power plant in South Sumatera, Indonesia (hereafter referred to as the Host Country ). The Project s net installed capacity is 2 x 55 MW 2, while its total gross power output will be 2 x 58 MW. An estimated power generation of 867 GWh per annum (based on the predicted load factor of 90% multiplied with the net installed capacity) will be supplied to the grid operator. The Project is a Greenfield project because there have not been any major activity e.g. well drilling dedicated to supply steam to Lumut Balai II. The key purpose of the project is to utilise the geothermal resources of the mountain areas surrounding Lumut Balai to generate electricity to be transmitted to the Sumatera Interconnected grid (hereafter referred to as the Grid) through the Perusahaan Listrik Negara (PT. PLN (Persero)), state-owned electricity company) interconnection point in the Lumut Balai geothermal project area. In the absence of the proposed project activity, electricity would be supplied by the generation mix in the Sumatera interconnected grid. The project activity will reduce total emissions in the Sumatera grid by supplying green renewable electricity from geothermal resources in the Lumut Balai geothermal field, instead of utilizing typical power generation with more carbon intensive technology. Total GHG emission reductions for the first crediting period (7 years) is estimated to be 4,072,488 tco 2 e, with annual average amount of 581,784 tco 2 e. The project is contributing to sustainable development of the Host Country 3. Specifically, the project: Increasing community development and corporate social responsibility at Lumut Balai geothermal field, as this project shows great improvement to existing geothermal field operation (social sustainability) Enhances the local investment environment and therefore improves the local economy, increases employment opportunities as persons will be permanently employed for the project activity operation, another 40 persons will be employed for the Lumut Balai geothermal field, and the construction of the project provides employment in the construction sector (economic sustainability) Diversifies the sources of electricity generation, which is important for meeting growing energy demands and facilitates the transition away from diesel and coal-supplied electricity generation (environmental sustainability) Makes greater use of geothermal renewable energy generation resources for sustainable energy production with leading local contractor (technology sustainability) 1 Lumut Balai II is Lumut Balai Unit 3 4 geothermal power plant that is owned and operated by PT. Pertamina Geothermal Energy. The Lumut Balai II is distinct and independent from Lumut Balai I (the power plant Lumut Balai Unit 1 2 geothermal) that is now under request for registration process. 2 As per technical specification documentation that was sent to PLN in October 2010, 2 x 58 MW is Lumut Balai II s power output or total gross installed capacity as per turbine s nameplate. While 2 x 55 MW is the net installed capacity, which the project developer used in the Power Purchase Agreement with PLN dated on 11 March The difference between power output or total installed capacity and net installed capacity, which is 2 x 3 MW, will be covering power plant auxiliaries (referred also as the project developer s internal consumption). 3 Sustainable Development criteria defined by the National Commission on Climate Change (representative of Indonesian DNA)

3 UNFCCC/CCNUCC CDM Executive Board Page 3 A.2. Location of project activity A.2.1. Host Party(ies) >> Republic of Indonesia A.2.2. Region/State/Province etc. >> South Sumatera province. A.2.3. City/Town/Community etc. >> Muara Enim regency, Semende Darat Laut sub-district. A.2.4. Physical/Geographical location >> Figure 1 Location of Lumut Balai 3-4 Geothermal Power Plant. Source: Google Earth Lumut Balai II geothermal power plant is located approximately 400 km east of Palembang, the capital of South Sumatera province. The exact location of the geothermal power plant is defined using GPS coordinates South, East. A.3. Technologies and/or measures >> The Project uses well-established geothermal power plant technology for electricity generation and transmission, with total gross power output of 2 x 58 MW and net installed capacity of 2 x 55 MW. The Project consists of a geothermal power plant with a steam turbine generator, gas extraction system, switchyard and utility system. The steam for the project will be provided by active geothermal wells from

4 CDM Executive Board Page 4 the Lumut Balai geothermal field, with condensate re-injection wells to maintain groundwater supply. The main technical parameters of the proposed project are shown in Table 1. Table 1 Main technical parameters of the proposed project Variable Value Source Turbine generator capacity (MW) 2 x 58 Power plant technical specification as sent to PLN, page D-25 Net installed capacity (MW) 2 x 55 Feasibility Study Report, page 12 Operating time yearly (hours) 7884 (8760 x 90%) Expected annual power generation / effective supply to the grid (MWh) Calculated based on 90% load factor as per Feasibility Study Report, page ,240 Feasibility Study Report, page 12 The Project will utilise state of the art but known technology in electricity generation and transmission. The geothermal steam turbine generator systems and other equipments e.g. cooling system must be imported. All supporting equipments used in the Project are produced domestically, whereby the project developer is experienced in handling and operating equipment of this nature. Steam collected from the Lumut Balai geothermal field is sent to the Lumut Balai II power plant, where it is separated from condensate and fed into steam turbine generator systems (direct steam expansion). Returning condensate from the turbine and steam separator is then collected and re-injected back into the geothermal field area. Electricity produced is sold to PLN. Figure 2 Lumut Balai II Geothermal Power Plant (wells and power plant Unit 3-4)

5 CDM Executive Board Page 5 A.4. Parties and project participants Party involved (host) indicates a host Party Republic of Indonesia (host) Switzerland Private and/or public entity(ies) project participants (as applicable) PT. Pertamina Geothermal Energy South Pole Carbon Asset Management Ltd. Indicate if the Party involved wishes to be considered as project participant (Yes/No) No No A.5. Public funding of project activity >> The project does not involve public funding from any Annex 1 countries.

6 CDM Executive Board Page 6 SECTION B. Application of selected approved baseline and monitoring methodology B.1. Reference of methodology >> 1. The baseline and monitoring methodology ACM0002 is used: Consolidated baseline methodology for grid connected electricity generation from renewable sources version , in effect as of 2 March 2012; 2. The Tool to calculate the emission factor for an electricity system, version 2.2.1, in effect as 29 September 2011; 3. The Tool to calculate project or leakage CO 2 emissions from fossil fuel combustion, version 02, in effect as of 2 August 2008; 4. The tool for demonstration and assessment of additionality used is: Tool for demonstration and assessment of additionality, version 06, in effect as of 25 November Further information with regards to the methodology can be obtained at: B.2. Applicability of methodology >> The Methodology chosen is applicable to the proposed project due to the following reasons: Table 2 Applicability Conditions of ACM0002 Methodology ACM0002 This methodology is applicable to grid-connected renewable power generation project activities that (a) install a new power plant at a site where no renewable power plant was operated prior to the implementation of the project activity (greenfield plant); (b) involve a capacity addition; (c) involve a retrofit of (an) existing plant(s); or (d) involve a replacement of (an) existing plant(s). The project activity is the installation, capacity addition, retrofit or replacement of a power plant/unit of one of the following types: hydro power plant/unit (either with a run-ofriver reservoir or an accumulation reservoir), wind power plant/unit, geothermal power plant/unit, solar power plant/unit, wave power plant/unit or tidal power plant/unit; In the case of capacity additions, retrofits or replacements (except for capacity addition projects for which the electricity generation of the existing power plant(s) or unit(s) is not affected): the existing plant started commercial operation prior to the start of a minimum historical reference period of five years, used for the calculation of baseline emissions and defined in the baseline emission section, and no capacity addition or retrofit of the plant has been undertaken between the start of this minimum historical reference period and the implementation of the project activity; CDM Project Activity The project is a grid-connected renewable power generation that install a new power plant at a site where no renewable power plant was operated prior to the implementation of the project activity (greenfield plant). The project is an installation of geothermal power plant / unit. The project is not a capacity addition, retrofits or replacements. It is a development of new power generation facility. On the basis of the reasons stated above, the applicability criteria of the methodology are met.

7 CDM Executive Board Page 7 B.3. Project boundary Baseline scenario Project scenario Source GHGs Included? Justification/Explanation CO 2 emissions from electricity generation in fossil fuel fired power plants that is displaced due to the project activity Fugitive emissions of CH 4 and CO 2 from noncondensable gases contained in geothermal steam CO 2 emissions from combustion of fossil fuels required to operate the geothermal power plant CO 2 Included According to ACM0002 only CO 2 emissions from electricity generation should be accounted for (main emission source) CH 4 Excluded According to ACM0002 (minor emission source) N 2 O Excluded According to ACM0002 (minor emission source) CO 2 Included According to ACM0002: CO 2 fugitive emissions from non-condensable gases should be accounted for (main emission source) CH 4 Included According to ACM0002: CH 4 fugitive emissions from non-condensable gases should be accounted for (main emission source) N 2 O Excluded According to ACM0002 (minor emission source) CO 2 Included According to ACM0002: CO 2 emission from fossil fuels combustion should be accounted for (main emission source) CH 4 Excluded According to ACM0002 (minor emission source) N 2 O Excluded According to ACM0002 (minor emission source) B.4. Establishment and description of baseline scenario >> Lumut Balai II power plant or the Project is an independent, distinct power plant from Lumut Balai I power plant. Even though both power plants share the same Lumut Balai geothermal field, each of them has a separate steam supply system with a separated steam header. Under the Power Purchase Agreement (PPA) between PGE and PLN, Lumut Balai II supplies generated electricity to the Sumatera interconnected grid. Since this project does not modify or retrofit existing electricity generation facilities the baseline scenario is the following: Electricity delivered to the grid by the project would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the latest exante combined margin (CM) value, which is available at the time of validation starts, in Table 3. Table 3 Key Information and Data Used to Determine the Baseline Scenario

8 CDM Executive Board Page 8 Variable Value / Unit Source Operating Margin Emissions factor tco 2 e / MWh Build Margin Emissions Factor tco 2 e / MWh Combined Margin Emissions Factor tco 2 e / MWh PLN database (own generation and IPPs) in cooperation with the Indonesian DNA and the Ministry of Energy Generation of the project in year y 867,240 MWh 110 MW x 90% x 24 hours x 365 days In the absence of the project electricity will continue to be generated by the existing generation mix operating in the Sumatera grid. Three realistic and credible alternatives to the project activity are considered to investigate the baseline: Alternative 1: The proposed project activity implemented without CDM financing, i.e. the construction of a new geothermal power plant with net installed capacity of 110 MW connected to the local grid, implemented without considering CDM revenues. This alternative is in compliance with current laws and regulations of Indonesia. However, according to the investment analysis in section B.5, the proposed project activity without CDM revenues is economically unattractive, and therefore is not a realistic baseline scenario. For a full assessment, please see section B.5. Alternative 2: Continuation of the current situation, i.e. electricity will continue to be generated by the existing generation mix operating in the grid, with capacity additions as planned. This alternative will be considered as the baseline scenario. Alternative 3: Construction of a thermal power plant with the same installed capacity or the same annual power output. This alternative is in compliance with the existing laws and regulations in Indonesia; there are no laws or regulations prohibiting the construction of such a thermal power plant (gas, diesel or coal-fired power plant). Out of these power plants, gas power plants will have technical barriers, since there is no gas pipeline constructed in the Lumut Balai mountain area. Construction of a diesel power plant will face less barriers to implement, however, with the increase in fuel price, it is expected that the operational cost of such a power plant will be very high; thus the generation cost per kwh is expected to be very high. The construction of a coal-fired power plant could also be considered as a potential baseline. Thus both the continuation of the current situation (Alternative 2) and the construction of a coal-fired power plant (Alternative 3) are possible baseline alternatives. In order to be conservative, the baseline scenario with the lowest emissions is selected for comparison; therefore alternative 3 will not be considered further. Alternative 4: Construction of renewable power generation with the same installed capacity or the same annual power output. This alternative is in compliance with the existing laws and regulations in Indonesia. However it is not plausible. PGE has no competencies in construction and operation of other renewable power generation (hydro, wind, solar etc.). Hence, this is not a plausible alternative to the project owner. In summary, two alternatives remain from this analysis, which will be examined in more detail in section B.5: Alternative 1 The proposed project activity implemented without CDM financing, i.e. the construction of a new geothermal power plant with net installed capacity of 110 MW connected to the local grid, implemented without considering CDM revenues.

9 CDM Executive Board Page 9 Alternative 2 Continuation of the current situation, i.e. electricity will continue to be generated by the existing generation mix operating in the grid, with capacity additions as planned. B.5. Demonstration of additionality >> The following steps are used to demonstrate the additionality of the project according to the latest version of the Tool for the demonstration and assessment of additionality agreed by the Executive Board for the assessment of alternatives please refer to B.4 : The start of the crediting period of this project activity is not prior to the date of registration, however for the assessment of additionality it is important to note that the CDM was taken into account when investment decisions were considered, and in the planning stages of the project. PT. Pertamina Geothermal Energy (PGE) is a subsidiary to PT. Pertamina (Persero), incorporated in December 2006 as a spin-off from Pertamina Upstream Division. Its core business is geothermal steam exploration and production (E&P), and therefore selling geothermal steam to power plant owners 4 currently in 2 major areas and 1 minor area. Lumut Balai I and II, which are located on the same Lumut Balai geothermal field are distinct and having separate steam systems coming from different identified wells. Both Lumut Balai I and II will be operating independently as a separate power plant even though both are located in Lumut Balai geothermal field. The project has not started any major activities e.g. well drilling, thus considered as a Greenfield project. Based on Lumut Balai II project plan, an estimated date to sign the contract for the 1 st well drilling is in 1 October 2012, which is then applied as the start date of the project. The following shows the timeline of historical work on the site, pre-project activity, and project development: Table 4 Lumut Balai II geothermal power plant historical progress Activity Date Remarks Environmental Impact Assessment / EIA report 21 August 2008 Approval by the environmental agency of Muara Enim regency PGE and PLN agreement facilitated by the National Development of Planning Agency (BAPPENAS) 13 July 2009 Signed Minutes of Meeting (MoM) describes PGE and PLN common interest to develop several geothermal fields in Indonesia FS report for power plant development (electricity generation and sales to the Grid) September 2009 Total investment = USD million (expected electricity price = USD 90/MWh) PGE Board of Directors and Board of Commissioners agreed to develop Lumut Balai II geothermal power plant as a total project. 21 January 2010 A Minutes of Meeting describes Board of Directors and Board of Commissioners decision to develop Lumut Balai II geothermal power plant. This date is considered as the investment decision date of the project Head of Agreement (HoA) 17 February 2010 Head of Agreement (HoA) is an agreement 4 Only in 2008 PGE started operating its own first geothermal power plant, a registered CDM project Kamojang unit IV geothermal power plant

10 CDM Executive Board Page 10 between PGE & PLN (for eight geothermal areas) CDM Prior consideration sent to the Indonesian DNA Confirmation of CDM prior consideration from the Indonesian DNA CDM Prior consideration sent to UNFCCC between seller e.g. PGE and buyer (e.g. PLN) before both parties entered into energy sales contract or steam sales contract such as: Steam sales = Ulubelu I, Lahendong IV, Hululais, Kotamobagu I-II, Sungaipenuh Electricity sales = Ulubelu II, Karaha, Kamojang, Lahendong V, Lumutbalai I-II 30 August 2010 Prior consideration published in the Indonesian DNA website as following: /index.php/komnasmpb/cat/4/database/2.html 4 September 2010 Letter to President Director of PGE from the Indonesian DNA regarding CDM prior consideration 16 September 2010 Prior consideration published in the UNFCCC website on 12 October 2010: /PriorCDM/notifications/index_html PPA signed with PLN 11 March 2011 Price = USD 7.53 cent / kwh (30 years from COD) ERPA signing with South Pole Carbon Asset Management Ltd. March 2012 Contract for 1 st well drilling work dedicated to supply steam to Lumut Balai II Signed ERPA between PGE and SP CAM Ltd. 1 October 2012 An estimated date of contract signing as per PGE written statement, which is considered as the project start date of the project Power plant construction 1 March 2014 Lumut Balai II project plan start Power plant operation start 1 January 2017 Lumut Balai II project plan Step 1. Identification of alternatives to the project activity consistent with current laws and regulations Sub-step 1a. Define alternatives to the project activity: Two remaining alternatives are considered: Alternative 1: The proposed project activity without CDM: construction of a new geothermal power plant with net installed capacity of 110 MW connected to the Grid, implemented without considering CDM revenues. Alternative 2: Continuation of the current situation. Electricity will continue to be generated by the existing generation mix operating in the Grid. Sub-step 1b. Enforcement of applicable laws and regulations: All alternatives are in compliance with all applicable legal and regulatory requirements of Indonesia. STEP 2. Investment Analysis

11 CDM Executive Board Page 11 According to the Tool for the demonstration and assessment of additionality, three options can be applied to conduct the investment analysis. These are the simple cost analysis (Option I), the investment comparison analysis (Option II) and the benchmark analysis (Option III). Sub-step 2a. Determine appropriate analysis method Since this project will generate financial / economic benefits other than CDM-related income, through the sale of generated electricity, Option I (Simple Cost Analysis) is not applicable. According to the Additionality Tool, if the alternative to the CDM project activity does not include investments of comparable scale to the project, then Option III must be used. Given that the Project Developer does not have alternative and comparable investment choices, the benchmark analysis (Option III) is more appropriate than investment comparison analysis (Option II) for assessing the financial attractiveness of the project activity. Sub-step 2b. Option III Application of benchmark analysis The likelihood of the development of this project, as opposed to the continued generation of electricity by the existing generation mix operating in the grid (i.e. Alternative 2 the baseline) will be determined by comparing the project IRR without CDM financing (Alternative 1) with a suitable benchmark that considers the specific context in which the proposed project activity takes place. According to the paragraph 13 of the Guidelines on the assessment of investment analysis in the case of projects, which could be developed by an entity other than the project participant, the benchmark should be based on publicly available data sources. The project activity could have been developed by any other entity, as long as this entity had the authorization to do it. This authorization can be transferred from one company to another, as happened to the project in the past 5. For this reason the benchmark has been duly derived from publicly available data sources. An appropriate benchmark value represents the minimum required return, which the project should earn to justify its financial viability. It has been determined according to the Tool for demonstration and assessment of additionality (hereinafter Tool ) and the Guidance on the assessment of investment analysis (hereinafter Investment Guidance ). The benchmark has been derived from government bond rates, increased by a suitable risk premium to reflect private investment in a particular industry; those parameters are based on information that is publicly available and standard in the market ( Tool, sub-step 2b, para.6a; Investment Guidance para.12). The risk premium applied reflects the risk of the project activity being assessed as required by the Investment Guidance (para.15) but does not relate to an internal benchmark that would apply an individual s perception of risk involved in the project activity or individual profit expectations ( Investment Guidance, para.13). The weighted average cost of capital (WACC) of the project activity is used as most appropriate benchmark to compare with the project s return ( Investment Guidance, para.12 in combination with para.14 WACC is an appropriate benchmark for a project IRR). The selected approach is widely accepted as a suitable approach among financial managers to take investment decisions. Financial data used in the benchmark determination is obtained from Indonesian or US long-term government bond rates, which are increased by an appropriate risk premium that expresses the additional (market and financing) risk of equity investments over returns on riskless assets. The Investment Guidance requires project participant to risk-adjust the benchmark according to the specific risk profile of the project activity, i.e. its market and financing risk (para.14). All information used in this financial 5 Renewable Energy in Asean: Indonesia-geothermal, refer to Table Suppliers and Manufacturers (PT. Daya Bumi Lumut Balai tried to negotiate Lumut Balai geothermal development, in 2004)

12 CDM Executive Board Page 12 analysis, including specific market risk is based on actual publicly available financial market information and provided by financial experts. Considering information available to the project developer, the project WACC was calculated based on the following inputs: Table 5 Values taken for benchmark determination Parameters Value Reference Geothermal tax rate 34 % Presidential Decree no. 49 issued in 1991 (T) Cost of Debt (CD) 3.98 % The lowest cost of debt for investment loans sourced from Indonesia s Central Bank statistic webpage is chosen among cost of debt of different bank groups prior to the investment decision. Cost of debt value refers to investment loan rate of foreign and joint bank in December Risk free rate (Rf) 4.08 % Lowest rate between an Indonesia government bond or US long term government bond. U.S long-term government bond is considered as risk free instrument. Bond rate is taken as the 1-year average (January to December 2009) prior to the investment decision and for a duration equal to the technical lifetime of the project activity, link: Total risk premium (RP) 9.00 % The total risk premium includes an Equity Risk Premium and a Country Risk Premium: The reason behind this premium stems from the risk-return trade-off, in which a higher rate of return is required to entice investors to take on riskier investments. These are risk premiums estimates for other countries outside of the U.S based upon the country ratings assigned by Moodys, link: "Risk Premium for other Markets". Value taken for Indonesia for period January to December 2009, which is publicly available in Jan 2010, link: Beta (unlevered) 1.95 Unlevered Total Beta is calculated based on power sector individual company data in emerging markets available at Prof. Aswath Damodaran website (Stern University). Data is taken from period of January to December 2009 before investment decision date, link: 09.xls % Debt 50 % As per EB 62, Annex 5, Para 17, 18 % Equity 50 % As per EB 62, Annex 5, Para 17, 18 Post-tax WACC % Calculated from above values as per ER-IRR-WACC calculation The formula applied to calculate the WACC is the following: Post-tax WACC 6 = [Cost of Equity(%) x Equity Proportion(%)] + [Cost of Debt(%) x Debt Proportion(%) x (1 Tax rate)] Determination of Cost of Equity 6

13 CDM Executive Board Page 13 The cost of equity is determined by utilizing the Capital Asset Pricing Model (CAPM). The CAPM defines the compensation of investors for investments taken. One part of the formula is related to the time value of money (risk free rate) compensating for investment over a time period, the other part represents the risks for investment. This is calculated by taking a risk measure, so called beta (β). The beta compares the returns of the asset to the market over a period of time and to the market premium. The formula correctly applied is as following: Total Cost of Equity Re = Risk Free Rate + [Total Beta levered x Total Risk Premium] = Rf + [Total β lev x RP] Total β lev =Total Beta unlevered x [1 + ((1-T) x (D/E))] Where: Re: Cost of equity Rf: Risk free rate Total β lev : Total Beta levered RP: Total Risk Premium T: Tax rate applied in the proposed project activity D/E; Debt/Equity ratio The applied model is internationally known 7 and applied in making investment decision. Explanation of input values to the Cost of Equity Rf: 4.08 % The risk free rate is determined from a 1-year average data (January to December 2009) of US government rate (long term, 30 years corresponding to the start date and the expected lifetime of the proposed project activity). These bond rates were available at the time of making the investment decision. The data for the Risk free rate is sourced from US Central Bank webpage 8, and the value of the Risk free rate can be found in the Risk free rate tab in Lumut Balai II ER-IRR-WACC calculation spreadsheet. Total β unlevered : 1.95 The unlevered total beta value is calculated based on individual company information in emerging markets for power sector information, as provided by Prof. Aswath Damodaran, a professor at Stern University. Data used in the calculation from January to December 2009 is the latest data available at the time of investment decision. The unlevered total beta is calculated from beta value of each company in small Asia region (exclude China and India), being unlevered with available company data for Tax rate and Book D/E ratio values, and subsequently the formula for Cash-adjusted Beta is applied to the resulting unlevered beta corrected for cash (with available company data for Cash/Firm value ), according to formula below 9 : Unlevered Beta = company Beta / [1 + ((1 Tax rate) x (Debt/Equity))] Unlevered Beta corrected for cash = Unlevered Beta / (1 Cash/ Firm Value) The value for each company unlevered Beta corrected for cash is then divided by available company data for Correlation with Market, to produce unlevered Total Beta corrected for cash

14 CDM Executive Board Page 14 Unlevered Total Beta = unlevered Beta corrected for cash / Correlation with Market Finally, average value for unlevered Total Beta is calculated from all companies in the Power sector and Small Asia region. The value of the unlevered Total Beta can be found in the Beta unlevered tab in Lumut Balai II ER-IRR-WACC calculation spreadsheet. RP: 9.00% The total risk premium 10 includes an Equity Risk Premium and a Country Risk Premium: The reason behind this premium stems from the risk-return trade-off, in which a higher rate of return is required to entice investors to take on riskier investments. These are risk premiums estimates for other countries outside of the U.S based upon the country ratings assigned by Moodys. Risk premium value is taken from period of January to December 2009, which can be found in the Country premiums tab in Lumut Balai II ER-IRR-WACC calculation spreadsheet. Cost of Equity as per CAPM approach: Re = Rf + [Total β lev x RP] = 4.08% + [3.24 x 9%] = % Cost of Debt: 3.98 % The interest rates / the lending rates statistics data by the Indonesian Central Bank (Bank Indonesia) are used as the cost of debt to calculate the WACC. The cost of debt has therefore been taken from the official data source. The Bank Indonesia 11 can be considered as credible and suitable data source for the purpose of the determination of the debt cost. The value corresponds to the lowest and most conservative investment loan rate in 2009, which refers to investment loan rate of foreign and joint bank in December 2009 (3.98 %, foreign and joint bank s investment loan, from Table I.27 Interest Rate of US Dollar Loans by Group of Banks). Geothermal tax rate: 34 % The reference used for Geothermal tax rate is the Presidential Decree which is a government regulation according to which the Geothermal projects are obliged to pay the 34% Tax, as per the Presidential Decree no. 49 / This tax rate has to be applied for geothermal projects in Indonesia. This tax rate was valid at the time of decision-making. Applying the above mentioned formulas and input values; the post-tax WACC is calculated as %. This value is used as the project IRR benchmark. Sub-step 2c. Calculation and comparison of financial indicators Upon obtaining the WACC, a financial analysis with Tax calculation of the project activity was carried out. Table 5 shows the input data as well as the key parameters used in the financial analysis. Every input value had a reasonable and reliable source, and was backed up by third party information, showing the reasonableness of the numbers applied, as follows: Electricity Tariff PGE expected to be able to sell generated electricity to PLN at the price of US$ 90 / MWh, in the Feasibility Study for Lumut Balai II power plant development. However, in March 2011 the Power 10 "Risk Premium for other Markets". Value taken for Indonesia. Most recent available Jan 2010, link: r/sektor+moneter.htm

15 CDM Executive Board Page 15 Purchase Agreement (PPA) was finally signed with significantly lower price than expected, US$ 75.3 / MWh. The highest price is used for PDD calculation, giving more conservative results to the IRR calculation. Annual operating costs The applied value is taken from the Feasibility Study: Upstream (steam field) O&M: US$ 30,000 / MW and Power Plant O&M: US$ 50,000 / MW, this is equivalent to US$ 8,800,000 / year or US$ / MWh. Specifically for Power Plant O & M costs (US$ 5,500,000 / year or US$ 6.3 / MWh) are significantly lower than the geothermal power plant O&M costs found in the study published by PT. Indonesia Power, an Indonesian geothermal power plant operator 12, and considerably lower than in international literature 13. However, the O & M cost does not yet include make-up wells maintenance cost in year 4, 10, 16 and 22 as per Table 6. Table 6 Financial Parameters for Lumut Balai II power plant Financial Parameter Unit Value References Total Investment US $ 276,350,000 Feasibility Study page 18 Annual Operation and US $ / year 8,800,000 Feasibility Study page 19 Maintenance (O & M) Costs Annual power generation MWh / year 867,240 Calculated based on net installed capacity 2 x 55 MW with capacity factor of 90%; Feasibility Study page 19 Project lifetime years 30 Feasibility Study page 15 Electricity tariff US $ / MWh Feasibility Study page 19 Geothermal Income Taxes % Presidential Decree no. 49 / 1991 Depreciation for upstream % Feasibility Study page 19 Depreciation for downstream % 5.00 Feasibility Study page 19 Make-up wells maintenance cost US $ 12,250,000 Feasibility Study page 23 in year 4 & 16 Make-up wells maintenance cost US $ 15,940,000 Feasibility Study page 23 in year 10 & 22 Residual make-up well (Year 22) US $ 3,188,000 Calculated, depreciation sheet Annual interest payment % 3.98 Investment rate value for foreign and joint bank from Central Bank of Indonesia statistic webpage Table 7 Summary of Project Financial Analysis Without CDM Post-tax IRR Benchmark Sub-step 2d. Sensitivity analysis A sensitivity analysis was undertaken using assumptions that are conservative from the point of view of analysing additionality, i.e. the best-case conditions for the project IRR were assumed. It was supposed 12 Kemampuan Sumper Daya Domestik Bindang Pembangkitan Dalam Mendukung Peningkatan Penyediaan Tenaga Listrik, published by PT Indonesia Power 2002 (Paper Indonesia Power O&M Costs comparison.pdf) - Operational Cost for a geothermal power plant equivalent to 8.93 US$/MWh) 13 Cost of geothermal power and factors that affect it Subir K. Sanyal (2004) - This document states operational costs of 2.0 to 1.4 cents US$ per kwh (14US$/MWh)

16 CDM Executive Board Page 16 that the Project experienced a) no change of original assumptions; b) increasing revenue (increase of electricity tariff or operating hours); c) capital costs decreased; d) operation and maintenance costs decreased. The results are shown in the table below. Deviations of 10% have been taken into account in the above decisive assumptions. The summary table is shown below. Table 8 Summary of project sensitivity analysis Scenario % change IRR (%) a) no change in original assumptions b) increase in project revenues 10 % c) decrease in investment costs 10 % d) decrease in O & M costs 10 % The variation in key parameters above were considered to be conservative because the parameters were not expected to vary by more than this amount (and are in fact not expected to vary in favour of the project at all) for the following reasons: A) Project revenue is unlikely to increase that much. Instead, final signed PPA price was 16 % lower than expected when PGE decided to develop the project. The PPA contract signed between PGE and PLN is unlikely to be revised upward during contract period, increasing the electricity price. It is not a common practice in the country neither in the sector. Revenues could be increased only by increasing the hours of operation. Assuming an increase in electricity generation through an increase of the overall load factor above, the IRR would increase but still below the benchmark. Even this increase is difficult to accomplish given the engineering constraints of a geothermal power plant, which requires regular and sufficient maintenance to ensure safe operation and performance over the lifetime of the equipment. Increasing the load factor above 90 % would jeopardise power plant maintenance. Therefore increasing revenues by % to breach the benchmark is not possible to happen. B) Investment costs are unlikely to decrease the amount necessary to make the project profitable by the time of decision-making. The short-term trend of investment costs is to continue this escalation. In addition to that, an increase of raw material and fuel price globally results in upward price pressure for equipment. To further justify that total investment cost will unlikely to decrease is a higher average cost of well drillings that have been developed by PGE at Lumut Balai geothermal field for Lumut Balai I geothermal power plant compare to PGE assumption in the Feasibility Study of Lumut Balai II geothermal power plant. The average cost of already drilled wells in Lumut Balai I geothermal power plant is 4.3 Mill USD per well, while cost assumption used in the Feasibility Study of Lumut Balai II geothermal power plant is only 4 Mill USD per well. In addition to that, as a comparison with other similar geothermal projects that also consider upstream and downstream costs, which are now under validation such as Rantau Dedap 14 (USD 3,434/kW), Gunung Rajabasa 15 (USD 2,986/kW), Liki Pinangawan Muaralaboh 16 (USD 3,592/kW), Lumut Balai II (USD 2,512/kW) investment cost is much more lower. Besides that, based on International Energy Agency study in , Lumut Balai II cost per kw is lower than their average indicative cost, which is USD 4,000/kW. Therefore decreasing investment 14 Rantau Dedap geothermal power plant, 15 Gunung Rajabasa geothermal power plant, 16 Liki Pinangawan Muaralaboh geothermal power plant, 17 Geothermal Heat and Power, International Energy Agency ETSAP, May 2010

17 CDM Executive Board Page 17 costs by % to breach the benchmark is quite unlikely to happen for Lumut Balai II as the investment cost is already very low. C) Operation and maintenance costs including make-up wells are also unlikely to significantly decrease during the operation period. The costs presented on the feasibility study include only fixed costs based on the installed capacity of the equipment. The fixed costs include the Power Plant O&M and the upstream costs on the geothermal field (US$ 30 / kw for upstream costs and US$ 50 / kw for power plant O&M, totalizing US$ 8,800,000 / year). Even with decreasing operation and maintenance costs by 89.50% the project remains still unattractive. These results show that even under very favourable, although unreasonable, circumstances the Project IRR is still not higher than the benchmark for similar investments under similar conditions in the host country. Therefore we can conclude that the Best Case IRR is not financially attractive, and the proposed project without CDM (alternative 1 Baseline Scenario) overall is also not financially attractive. STEP 3. Barrier Analysis Barrier analysis was not performed for this project activity. STEP 4. Common Practice Analysis Sub-step 4a. Analyse other activities similar to the proposed project activity Indonesia is defined as the geographical scope for the common practice analysis, and all geothermal power plants operational at the time of decision-making are considered in the analysis. Indonesia has significant geothermal energy potential due to the volcanic zone, which stretches along the southern coast of Sumatera and Java. Geological Agency conducted surveys to have an insight of geothermal potential in all location in Indonesia. Until November 2007, a total of 27,441 MW geothermal potential calculated from 256 prospects area with 62.1% of them are still on preliminary survey stage, while 32.04% on detailed survey stage, 3.13% are ready to be developed and only 2.73% are producing 18. Total geothermal potential until November 2007 is 27,441 MWe, of this potential, 13,273 MWe are located in Sumatera Island, 9,556 MWe are scattered across Java Island and remaining 4,612 MWe geothermal potential are divided between other Islands 19. Despite this potential, however, only a small proportion of the geothermal resource has been exploited. The proportion of grid electricity coming from geothermal in Indonesia is very low, accounting for less than 5% of electricity generation in Indonesia in The geothermal capacity addition of 1% to total generation in the last 9 years, all were developed as CDM projects. The reasons for this are generally low rate of return and increased risks associated with geothermal plants when compared to other technologies, but economic uncertainties also play a role. Prior to the financial crisis, the Indonesian government awarded contracts for 11 geothermal projects that would have had a generating capacity of 3,417 MW 21. Due to the tight fiscal constraints imposed by the crisis and the political change that followed, 7 of the above projects were suspended. 18 Kasbani, et. al., Kesiapan Data Potensi Panas Bumi Indonesia Dalam Mendukung Penyiapan Wilayah Kerja, Proceeding Pusat Sumber Data Geologi, page 1 19 Kasbani, et. al., page 5 20 Darma, Surya, et. al., Geothermal in Indonesia: Government Regulations and Power Utilities, Opportunities and Challenges of its Development, Proceedings World Geothermal Congress 2010, Bali, Indonesia US Embassy Report, Indonesia s Geothermal Development, Jakarta, Indonesia, 2002

18 CDM Executive Board Page 18 All geothermal power plants operational at the time of decision-making are considered in the analysis. By , geothermal electric power generation capacity in Indonesia was 1,187.3 MWe. This figure includes currently operating facilities at Sibayak (12 MWe) in the Sumatera grid. This also represents just 4.3 % of the estimated geothermal potential of 27,441 MW 23. Table 9 Operational Geothermal Power Plants in Indonesia No Power Plant 24 <Location> (Capacity) 1 Kamojang 25 unit I, II, III <Jawa> (140 MW) 2 Kamojang 26 unit IV <Jawa> (60 MW) 3 Salak 27 phase 1 <Jawa> (165 MW) 4 Salak 28 phase 2 <Jawa> (165 MW) 5 Darajat 29 phase 1 <Jawa> (55 MW) 6 Darajat 30 phase 2 <Jawa> (70 MW) 7 Darajat 31 phase 3 <Jawa> (110 MW) 8 Dieng 32 unit 1 <Jawa> (60 MW) Commencement date Unit Unit 2, December 2007 Unit 1, Unit Steam Field Operator Pertamina (state owned company) Pertamina (state owned company) Unocal / Chevron (IPP) 1997 Unocal / Chevron (IPP) Power Plant Operator PLN (state owned electricity company) Pertamina (state owned company) PLN (state owned electricity company) Unocal built and operated for 15 years, then transfer operations to PLN (stateowned) under BOT scheme 1994 Chevron (IPP) Indonesia Power (subsidiary of PLN, stateowned) With or Without CDM Activity Without CDM activity CDM activity Without CDM activity Without CDM activity Without CDM activity 2000 Chevron (IPP) Chevron (IPP) Without CDM activity 2006 Chevron (IPP) Chevron (IPP) CDM activity 1998 California Energy (IPP) developed, then transferred to Geo Dipa Energi (JV between Pertamina and PLN, both state- California Energy (IPP) developed, then transferred to Geo Dipa Energi (JV between Pertamina and PLN, both state-owned) Without CDM activity 22 Darma, et. al, Geothermal in Indonesia: Government Regulations and Power Utilities, Opportunities and Challenges of its Development, page 1 23 Kasbani, et. al., Kesiapan Data Potensi Panas Bumi Indonesia Dalam Mendukung Penyiapan Wilayah Kerja, Proceeding Pusat Sumber Data Geologi, page 1 24 US Embassy Report, Indonesia s Geothermal Development, Jakarta, Indonesia, 25 Registered CDM Project: Kamojang Geothermal Project PDD, 26 Registered CDM Project: Kamojang Geothermal Project PDD, 27 Registered CDM Project: Darajat Unit III Geothermal Project PDD, 28 Registered CDM Project: Darajat Unit III Geothermal Project PDD, 29 Registered CDM Project: Darajat Unit III Geothermal Project PDD, 30 Registered CDM Project: Darajat Unit III Geothermal Project PDD, 31 Registered CDM Project: Darajat Unit III Geothermal Project PDD,

19 CDM Executive Board Page 19 No Power Plant 24 <Location> (Capacity) 9 Wayang Windu 33 phase 1 <Jawa> (110 MW) 10 Wayang Windu 34 phase 2 <Jawa> (110 MW) 11 Lahendong 35 I <Sulawesi> (20 MW) 12 Lahendong II 36 <Sulawesi> (20 MW) 13 Lahendong 37 III <Sulawesi> (20 MW) 14 Sibayak I 38 <Sumatera> (2 MW) 15 Sibayak II and III 39 <Sumatera> (11.3 MW) 16 Ulumbu 40 <East Nusa Tenggara> (5 MW) Commencement date Steam Field Operator owned) 1997 Mandala Magma Nusantara (IPP) 2009 Mandala Magma Nusantara (IPP) 2001 Pertamina (state owned company) 2007 Pertamina (state owned company) 2009 Pertamina (state owned company) 2000 Pertamina (state owned company) 2008 Pertamina (state owned company) 2011 Pertamina (state owned company) Power Plant Operator Mandala Magma Nusantara (IPP) Mandala Magma Nusantara (IPP) PLN (state owned electricity company) PLN (state owned electricity company) PLN (state owned electricity company) Pertamina (state owned company) PT. Dizamatra Powerindo (IPP) PLN (state owned electricity company) With or Without CDM Activity Without CDM activity CDM activity Without CDM activity CDM activity CDM activity as LoA has been approved and prior consideration has been sent. Without CDM activity CDM Activity CDM activity as prior consideration has been sent 41. Sub-step 4b. Discuss any similar options that are occurring Based on the above step, there is no activity similar to the proposed project activity in the defined region. It is thus concluded that the realistic baseline scenario is the continuation of the current situation, where electricity will continue to be generated by the existing generation mix operating in the grid, with capacity additions as planned (Alternative 2). Based on the Tool for the demonstration and assessment of additionality (version 6), the applicable geographical area covers the entire country of Indonesia. The steps outlined in the Tool is followed: 32 Geodipa, 33 Registered CDM Project: Wayang Windu phase 2 Geothermal PowerProject PDD, 34 Registered CDM Project: Wayang Windu phase 2 Geothermal PowerProject PDD, 35 Registered CDM project Lahendong II-20 MW Geothermal Project PDD, 36 Registered CDM project Lahendong II-20 MW Geothermal Project PDD, 37 Indonesian DNA Letter of Approval for 20 MW Lahendong III was granted in February Sibayak 1 is a 2 MW mono-block geothermal power plant, 39 Under validation Sibayak geothermal power plant, 40 Ulumbu geothermal has been generating electricity, (retrieved on 7 December 2011) 41 Prior consideration under 6 MW Geothermal Project in Ulumbu, Flores, Indonesia,